A field of the invention is gas treatment. A particular exemplary application of the invention is to flue gas treatment, such as from flue gases of power plants. The invention is particularly applicable to treatment of gas streams.
Conventional coal-firing plants use a steam cycle for power generation. Steam cycles are also used in newer power plants, such as Integrated Gasification Combined Cycle (IGCC) power plants or Natural Gas Combined Cycle (NGCC) power plants. In a conventional steam cycle power plant, only about one-third of the heat energy contained in the fossil fuel is converted to electricity. This leaves more than half of the energy wasted in the water cooling towers. The water cooling tower transfers all of the waste heat in the low pressure exhaust steam (1.2 psia, 107.8° F.) to the environment through the vaporization of cooling water.
On the other hand, CO2 separation from post-combustion flue gas requires a large amount of heat (in the form of steam). For example, the current state-of-the-art monoethanol amine (MEA) absorption process requires about 4 MJ of total heat for every kilogram of CO2 captured. The steam that carries the heat has a pressure of around 60 psia. An absorption process that uses steam at a much lower pressure will have a significant advantage over the MEA-based absorption process.
Conventional CO2 separation processes are energy intensive. The required energy is provided by steam in the power plant. The extraction of steam from the steam turbine reduces the electricity generation (output). For the same amount of steam, the higher the pressure (and thus the temperature) of the extracted steam is, the higher the loss of the electricity will be. State-of-the-art amine-based absorption processes reduce electricity output by about 30%. For example, the installation of an MEA-based process in a steam cycle power plant will reduce its net electricity output from 500 MW to around 350 MW.
This energy cost, and the associated financial cost, inhibits the adoption of CO2 separation. With conventional MEA-based absorption processes, the cost of CO2 separation from post-combustion flue gases takes more than 80% of the total CO2 sequestration cost. High separation cost is the main reason for the delaying of CO2 emission control. High CO2 separation cost is also hindering the acceptance of CO2 based Enhanced Oil Recovery (EOR) technology.
CO2 emission control from power plants is not regulated at this time in the United States. There are several thousand power plants in the United States alone. If CO2 emission control becomes mandatory, an efficient and cost-effective process will be required. If voluntary reductions of emissions are to be encouraged, the cost of emission control must also be reduced. Currently, the CO2 emission level in the United States is about 20% above the level of 1990. A goal defined by the Kyoto protocol is that the United States needs to control around 20% of CO2 emission, which is about 12 Billion metric tons annually, equivalent to 300 of 500 MW power plants. Acceptance and adoption of CO2 separation, whether voluntary or by treaty or regulation, requires an improved CO2 separation process.